1. Field of the Invention
The invention relates to methods and apparatus used to measure the characteristics of fluid flowing through a well during hydrocarbon production. More particularly, the invention relates to a probe and signal processing methods for determining the volumetric flow rates of one or more of the fluid constituents in a well, and preferably for also determining the proportional volume of oil, gas, and water constituents in a well.
2. State of the Art
After drilling is completed, in many hydrocarbon wells the borehole is lined with a casing. In order to extract hydrocarbon fluids (oil and gas) from the formation surrounding the borehole, holes are made in the wall of the casing. The location of the holes is usually determined by reference to information acquired about the formation during the drilling operation, and/or after drilling with the aid of logging instruments before the casing is installed.
Various methods are used to urge the fluid out of the formation, into the well, and up to the surface. In most cases, the fluid travelling to the surface is a mixture of two or three fluid components (phases): oil (liquid hydrocarbon), hydrocarbon gas, and water (or brine). The fluid is collected at the surface and is handled in different ways, depending on the relative proportion of each phase. For example, if the fluid contains a relatively small amount of gas, the gas may be burned at the well site since it is not economically practical to process small amounts of gas. If the fluid contains relatively large amounts of water, it may be economically impractical to continue production operations at the site. In fact, even while the well is producing petroleum products, the disposal of water produced from the well is very costly. In general, the different phases of the well fluid enter the well from different locations, and a high water content can be the result of improperly located perforations in the casing. If it is possible to determine where water is entering the well, perforations in the casing can be plugged and the proportional amount of water in the fluid reduced.
The relative volumetric flow rates (flow rate fractions) of the oil, gas, and water through the well is known in the art as the "cut". The "holdup" is a measure of relative proportions of each phase in a selected volume of fluid in the well; i.e., the volume fraction. The cut and holdup are not in general the same, because the different phases may be, and are in general, flowing at different average speeds. In addition, both the volumetric flow rate and the volume fraction will vary over time and vary at different depths in the well.
Various methods and devices have been used for many years to estimate the volumetric flow rate and the holdup of each phase at different depths in a well over time. Most of the methods of the prior art measure volumetric flow rate or holdup averaged over the cross-sectional area of the wellbore. The principal devices for measuring flow rates employ propellers or turbines which are assumed to measure the average volumetric flow rate of the entire fluid mixture. However, propellers and turbines are typically ineffective in providing even their limited quantitative measurement when the well is not substantially vertical (i.e., when the well deviates more than five degrees from vertical).
Other devices of the art measure differential pressure to determine the average density of the flowing mixture. These devices lose their accuracy when fluid flow rate is high or the well is substantially inclined. Still other methods and devices for measuring holdup include the use of electrical plates to measure capacitance of the fluid and make a determination of the fluid content based on variations in capacitance. Similar systems measure resistivity or measure dielectric constant in the presence of RF radiation.
Recent devices derive the wellbore cross-sectional averaged volumetric flow rate and holdup from a number of local measurements made within the wellbore. The accuracy of these averaged volumetric flow rate and holdup determinations depends on the accuracy of each local sensor (probe), the deployment of a sufficient number of probes, and, in the case of non-vertical wells, knowledge of multiphase flow in the inclined pipe. Thus far, the local sensors which have been used have been electrical sensors which respond to the resistivity of the fluids in the wellbore. However, electrical probes can only measure the holdup and volumetric flow rates of the dispersed phase (which in an oil-water system at an oil holdup of more than about 0.65 is the water).
A known method for measuring liquid flow rates of a continuous phase consists of injecting a radioactive tracer at a location downhole and detecting its later arrival at a location relatively uphole. However, the use of radioactive tracers is generally considered undesirable. Recently, non-radioactive gadolinium has been used as a tracer and detected by a pulsed neutron tool. However, the use of the pulsed neutron tool is known to have many disadvantages.
In order to overcome many of the disadvantages of the prior art, the previously incorporated related patent application suggests utilizing pairs of adjacent optical fiber probes as part of a tool which distinguishes between the phases of a multiphase fluid flow in a borehole. According to the related patent application, optical reflection measurements can discriminate between gas and liquid because of the relatively large contrast in the signal received when gas is present and when liquid is present. However, it is much more difficult to distinguish between oil and water because of the lower and variable contrast existing between the oil and water signals. State-of-the-art three-phase optical probes utilize the principle of total internal reflection (which relates to the refractive index of a fiber optic probe and the refractive index of fluid at the tip of the probe) to make a determination of whether the fluid is a gas or a liquid. These systems, which are disclosed in the previously incorporated related application, utilize oblique ended probes where the angle of the tip face is carefully chosen relative to the refractive indices of the fluid components. In addition, the probe tip is preferably coated in order to prevent water wetting of the probe tip from interfering with oil detection.
While it is theoretically possible to construct a single reflection probe which can distinguish oil from water and liquid from gas, it is at best difficult to do so using the techniques of the prior art. Due to the complications in choosing the correct angle, correctly orienting the probe, and coping with temperature and/or salinity induced changes in the refractive index of water, using prior art techniques, it is difficult to provide a single reflection probe with the ability to properly distinguish each of the three phases of fluid. Therefore, more robust reflective optical fluid analysis systems such as that disclosed in the related patent application utilize a pair of probes which are located in close proximity to each other. One probe is designed to distinguish liquid from gas and the other is designed to distinguish oil from "not oil". However, it will be appreciated that such systems are still subject to error, as the closely located probes may see different parts of the multiphase fluid stream and may affect the flow around the other and hence the accuracy of measurement.